Tar sands, such as are found in Alberta, Canada, contain vast reserves of hydrocarbon resources, of the type referred to as heavy oil and bitumen. Heavy oil means crude oil that has high specific gravity and viscosity. These characteristics make it difficult to extract the oil from the typically tightly packed sand formations found in tar sands, because, unlike lighter oil deposits, heavy oil and bitumen do not readily flow.
In the past steam has been injected into the oil-bearing formation to improve the rate of bitumen and heavy oil extraction. There are a number of different stream extraction techniques, including steam cycling, steam floods and more recently steam assisted gravity drainage, commonly known as SAGD. The steam raises the temperature of the oil thereby reducing its viscosity and allowing it to flow more easily. Steam extraction is subject to a number of problems, including heat losses during injection, clay swelling problems, thief zones, water-oil emulsions, capillary surface tension effects and lack of confinement for shallower zones, and therefore is not widely used.
Thermal recovery processes using steam also require using large amounts of energy to produce the steam in the first place, which releases enormous amounts of greenhouse gases such as carbon dioxide. For example, a 100,000 bbl oil/day facility requires 200,000-300,000 bbl water/day to be converted into steam at 200C. Therefore, if fueled by natural gas, a 100,000 bbl oil/day extraction facility will produce more than 12 million pounds per day of carbon dioxide emissions. With the high cost of natural gas, many operators will use less expensive coal, coke or bitumen. However, such fuels generate about twice as much carbon dioxide emissions per bbl of steam as natural gas. Thus, fuel substitution could potentially double the carbon dioxide emissions to 24 million lbs/day for a 100,000-bopd SAGD facility. In other words, to recover just one barrel of bitumen by steam produces about 240 lbs of carbon dioxide emissions. Therefore, a better recovery technique than steam injection is highly desirable.
Nenniger1 (1979) first proposed the idea of replacing steam with cold (unheated) solvent vapour such as ethane or carbon dioxide for deep deposits and producing the heavy oil by gravity drainage. However to date there has not been a successful commercial pilot of this cold solvent approach. The predicted production rates from laboratory tests are simply too slow to yield a cost effective treatment. Bench tests2 using solvent (propane) and sand have shown that production rates can be increased about 20 fold simply by increasing the extraction temperature from 20C to 90° C. However, Butler2 indicated that propane was unsuitable for direct heating and proposed indirect heating of the propane vapour by co-injection of hot water. However, co-injection of steam or hot water which is heated above grade also suffers from a number of problems, such as countercurrent heat exchange problems during startup, formation damage problems with clays, and non-Newtonian emulsions, capillary pressure issues, water treatment, water supply, and reduced oil permeability due to high water saturations.
1 Nenniger, E. H., Hydrocarbon Recovery, Canadian Patent 1,059,432 
2 See Table 1 and FIG. 7 of Butler et al, A New Process for Recovering Heavy Oils using Hot Water and Hydrocarbon Vapours, JCPT January 1991, pg 100 
Canadian patent application 2,235,085 by John Nenniger teaches using a downhole heater to heat and vaporize solvents in situ to quickly grow the solvent chamber. This prior patent application teaches that a re-boiling of the solvent in the hot zone and then re-condensation (reflux) at the bitumen interface can occur, for enhanced recovery. Subsequently, two patent applications of Suncor Energy Inc. 2,304,938 and 2,281,276 were filed which repeat the teachings of using a downhole heat source to set up an in situ reflux cycle for a solvent, comprised of for example a combination of propane and waste CO2.
Another approach is taken in patent application 2,299,790 by John Nenniger, which discloses the latent heat of condensation of several fluids as a function of temperature at their respective vapour pressures. It teaches that to reduce the extraction temperature below SAGD (i.e. to reduce energy costs and greenhouse gas emissions) then the only suitable gases to deliver heat are propane, butane and pentane and the like. Steam has such a low volumetric heat capacity that is unsuitable at lower extraction temperatures. Ethane has such a low critical temperature that it is unable to deliver latent heat above about 30C. This prior application teaches, for example, that if the Stokes-Einstein law applies, then at 40C the diffusion coefficient is expected to be about 100 times larger than the diffusion coefficient at 8C (i.e. original reservoir temperature).
The prior patent application also teaches the expected extraction rate as a function of extraction temperature. For comparison, non-thermal vapour extraction rates (such as Vapex) are about 1 cm/day while SAGD extraction rates (at 200C) are about 5 cm/day. While the curves of the prior patent application are theoretical and may differ from experimental measurements, the key point is that moderate temperature increases in the bitumen are expected to provide dramatically accelerated bitumen extraction rates. With the added benefit of solvent dilution and deasphalting (as compared to a steam process which is purely thermal), the condensing solvent extraction process taught offers the potential for much higher extraction rates than SAGD at much lower temperatures.
Typically, experiments done on tar sand deposits have been performed on recovered samples. Such recovered samples do not have the same characteristics as the in situ oil, having undergone a temperature and pressure change in the process of recovery. Although various forms of condensing heat transfer such as SAGD, and the Suncor reflux system have been proposed, the effect of light gases which are difficult to condense in an extraction or solvent chamber process have neither been understood nor accounted for. This may be because such light gases are typically lost before samples are placed in laboratory tests, meaning that testing results are obtained from “dead” samples.